FIELD OF THE DISCLOSURE

The present disclosure relates in general to methods for reconditioning used and damaged steel pipe, particularly pipe used as production tubing in the oil and gas industry.

BACKGROUND

In common methods for producing oil from a well drilled into an oil-bearing subsurface formation, a string of steel production tubing is positioned in the wellbore and extends from a subsurface production zone up to a pump jack at the surface. Typical production tubing has a nominal diameter of 2, 2½, 3, or 4 inches (with respective actual outside diameters of 2.375, 2.875, 3.500, and 4.500 inches). The tubing is provided in lengths (or "joints") up to 30 feet long, with external threads on each end. The tubing string is made up by connecting multiple tubing joints end to end, using tubular couplings having internal threads matching the external threads on the tubing joints.

A downhole pump is disposed within the production tubing in the production zone to raise well fluids (e.g., oil, gas, formation water) to the surface, by reciprocating vertical movement of a travelling valve incorporated into the pump. The travelling valve is reciprocated by a steel "sucker rod" extending upward within the production tubing to the wellhead, where it connects to a polished rod extending upward through a wellhead tee and stuffing box. The upper end of the polished rod is connected to what is commonly called the "horse head" at the free end of the "walking beam" of the pump jack. By means of a suitable motor and associated mechanical linkage, the pump jack is operable to rock the walking beam such that the horse head reciprocates up and down, thereby alternately raising and lowering the sucker rod and the travelling valve, causing well fluids to be drawn into the well and into the production tubing, and moved upward within the production tubing toward the wellhead on each upward stroke of the travelling valve. As the sucker rod reciprocates up and down within the production tubing, it inevitably comes into contact with the inside wall of the tubing. The resultant friction between the steel sucker rod and the steel tubing causes wear on the rod and the tubing.

Instead of using pump jacks, well fluids may also be produced using a wellhead apparatus that rotates the sucker rod to drive a downhole screw pump (also known as a positive displacement pump), rather than reciprocating the sucker rod up and down. Although rotating sucker rods thus function differently than reciprocating sucker rods, they are nonetheless prone to friction-induced wear due to contact with the tubing and can cause wear to the inner wall of the tubing. The machining of threads onto the ends of the tubing joints reduces the tubing's cross-sectional area, and therefore also decreases the tubing's structural strength. In order to avoid loss of cross-sectional area at the connections between tubing joints, pipe used for production tubing is commonly manufactured with "upset ends" - meaning that the outside diameter of the tubing is increased in the end regions that will be threaded, while the inside diameter (or I.D.) remains constant. Provided that the increase in diameter is equal to at least twice the depth of the threads, the minimum radial thickness of the wall of the upset end of the tubing will be equal to or greater than the wall thickness of the main portion of the tubing.

Production tubing is selected to have a wall thickness that will allow the tubing to remain safely in service even after some loss of wall thickness due to abrasion and wear. Tubing is periodically inspected for loss of wall thickness, and color-coded bands are applied to used tubing joints to indicate how much wall thickness has been lost. For example, a yellow band indicates 0-15% loss of wall thickness, a blue band 16-30%, a green band 31-50%, and a red band more than 50% loss of wall thickness. It may be appreciated, therefore, that a given joint of tubing could be in generally serviceable condition despite some loss of wall thickness, but the joint could nonetheless be unusable if there is significant damage to the upset threaded ends due to abrasion, impact (such as during pipe handling and transport), or other causes. A large quantity of used tubing is scrapped every year for such reasons. This result in a large waste of money and resources to replace the scrapped pipe with new pipe, when the scrapped pipe may well have been quite serviceable except for damage to the threaded ends.

For the foregoing reasons, there is a need for methods of reconditioning and extending the service life of used steel tubing, thereby minimizing the volume of tubing that needs to be discarded and replaced.

BRIEF SUMMARY

The present disclosure addresses this need by teaching methods for reconditioning tubing joints having serviceable tubing portions but unserviceable threaded upset ends. A tubing nipple of known type having threaded ends is transversely cut to produce two tubing nipple segments, and the unserviceable upset ends of the tubing joint are cut off and discarded. A tubing nipple segment is then substantially coaxially mated to and welded to each cut-off end of the serviceable tubing portion. The tubing nipple is preferably selected to have an inner diameter corresponding to the inner diameter of the tubing joint, and to have a net cross-sectional area through its threaded regions at least equal to the minimum cross-sectional area of the serviceable tubing portion.

Accordingly, in one aspect the present disclosure teaches a method for reconditioning a tubing joint comprising a tubing portion extending between threaded upset ends wherein at least one of the threaded upset ends is unserviceble, said method comprising the steps of:

• cutting through the tubing portion to remove at least one unserviceable threaded upset end, and salvaging the remaining tubing portion;

• providing a cylindrical tubing nipple having a center bore and externally threaded ends; · cutting the tubing nipple along a transverse tubing nipple cut-off line to produce at least one tubing nipple segment having a threaded end and a cut end; and • coaxially abutting the cut end of one said tubing nipple segment against one said cut end of the salvaged tubing portion, and welding the tubing nipple segment to the tubing.

In another aspect the disclosure teaches a tubing joint comprising a tubing portion having at least one upset threaded end, wherein the upset threaded end is cut from a tubing nipple and welded to one end of the tubing portion.

In a further aspect the disclosure teaches a method for reconditioning a tubing joint comprising a tubing portion extending between threaded upset ends wherein the tubing portion is unserviceable and at least one of the threaded upset ends is serviceable, said method comprising the steps of:

• cutting through the tubing along a transverse tubing cut-off line to remove the unserviceable tubing portion, and salvaging the at least one serviceable threaded upset end;

• providing a replacement tubing section; and

• coaxially abutting the cut end of one said salvaged threaded upset end against one end of the replacement tubing section and welding the salvaged threaded upset end to the replacement tubing section.

In yet another aspect the disclosure teaches a tubing joint comprising a tubing portion having at least one upset threaded end, wherein the upset threaded end is cut from a tubing joint comprising a tubing portion having at least one upset threaded end, with the upset threaded end being salvaged from a damaged tubing joint and welded to one end of the tubing portion. BRIEF DESCRIPTION OF THE DRAWINGS

Embodiments in accordance with the present disclosure will now be described with reference to the accompanying Figures, in which numerical references denote like parts, and in which: FIGURE 1 illustrates a conventional tubing nipple externally threaded at each end.

FIGURE 2 illustrates a tubing nipple as in FIG. 1 after being transversely cut into two tubing nipple segments for purposes of methods in accordance with the present disclosure. FIGURE 3 illustrates an end portion of a tubular member having an externally- threaded upset end, with the threaded upset end being unserviceable and at least part of the non-upset length of the tubular member being serviceable.

FIGURE 4 illustrates an end portion of a tubular member as in FIG. 3 after the unserviceable upset end has been removed and a tubing nipple segment as in FIG. 2 has been welded onto the salvaged serviceable length of tubing remaining after removal of the unserviceable upset end.

FIGURE 5 illustrates a salvaged serviceable length of tubing with a replacement end as in FIG. 4, indicating the optional removal of excess material after attachment of a tubing nipple segment. DETAILED DESCRIPTION

FIG. 1 illustrates an EUE 8RD tubing nipple 10 of a type well known to persons knowledgeable in the field. Tubing nipple 10 is essentially a straight piece of pipe having an inner diameter 11 and external threads 12 at each end, and tubing nipples of this type are available in a number of diameters. In one embodiment of a tubing reconditioning method in accordance with the present disclosure, a tubing nipple 10 of appropriate inside diameter and wall thickness is cut along a transverse cut-off line X as shown, to produce two tubing nipple segments 10A having cut ends 15 as shown in FIG. 2, which can then be used to fabricate replacement ends for damaged tubing joints.

FIG. 3 illustrates an end region of a joint 20 of used tubing having an inner diameter 21 and a threaded upset end 24 that is unacceptably worn or otherwise damaged and therefore unserviceable, but also having a non-upset portion 22 that is still serviceable. In accordance with this embodiment of the method, the unserviceable upset tubing end 24 is cut off along a transverse cut-off line Y and discarded.

FIG. 4 illustrates an end region of a reconditioned tubing joint 30 fabricated in accordance with the present method by substantially coaxially abutting the cut end 15 of a tubing nipple segment 10A against the cut-off end of a serviceable portion 22 of a used tubing joint 20 and welding tubing nipple segment 10A to used tubing portion 22 as indicated by weld 32. Tubing nipple segment 10A is preferably selected to have an inner diameter 11 corresponding to the inner diameter 21 of used tubing portion 22, and also to have threads 12 matching the threads on the discarded unserviceable upset tubing ends 24, thus facilitating the use of the same type of tubular couplings.

As indicated in FIG. 5, tubing nipple segment 10A, having a larger outside diameter than the salvaged tubing portion 22, is preferably trimmed to provide a smooth transition with the cut-off end of salvaged tubing portion 22, generally as indicated by reference number 34. This step may be carried out either before or after tubing nipple segment 10A is welded to salvaged tubing portion 22.

The cut-off ends of tubing portion 22 and/or the cut ends 15 of tubing nipple segments 10A are preferably prepared to facilitate full-penetration welding to connect tubing nipple segments 10A to tubing portion 22. Preferably, the steps of cutting tubing nipple 10 into two tubing nipple segments 10A and cutting off the unserviceable tubing end 24 will be carried out using automated (e.g., robotic) equipment to minimize or eliminate the need for subsequent machining of the cut surfaces to ensure a suitably mating fit. An unillustrated alternative tubing reconditioning method may be used to recondition tubing in which the tubing portion between the threaded upset ends is unserviceable due to damage or excessive wear but the threaded upset ends are still serviceable. In this alternative method, the serviceable threaded upset ends are cut off from the unserviceable tubing, and then welded onto either a length of new tubing or a length of used but serviceable tubing from which damaged ends have been cut off.

It will be readily appreciated by those skilled in the art that various modifications of methods in accordance with the present disclosure may be devised without departing from the scope and teaching of the present disclosure. It is to be especially understood that the disclosure is not intended to be limited to any described or illustrated embodiment, and that the substitution of a variant of a claimed feature or method step, without any substantial resultant change in operation or result, will not constitute a departure from the scope of the disclosure.

In this patent document, any form of the word "comprise" is to be understood in its non-limiting sense to mean that any item following such word is included, but items not specifically mentioned are not excluded. A reference to an element by the indefinite article "a" does not exclude the possibility that more than one of the element is present, unless the context clearly requires that there be one and only one such element.